Systems and Methods for Enhancing Production of Viscous Hydrocarbons From a Subterranean Formation

ABSTRACT

Systems and methods for enhancing production of viscous hydrocarbons from a subterranean formation. The methods may include heating a hydrocarbon solvent mixture to generate a vapor stream, injecting the vapor stream into the subterranean formation to generate reduced-viscosity hydrocarbons, and producing the reduced-viscosity hydrocarbons from the subterranean formation. The methods also may include selecting a composition of the hydrocarbon solvent mixture by determining a threshold maximum pressure of the subterranean formation, determining a stream temperature at which the vapor stream is to be injected into the subterranean formation, and selecting the composition of the hydrocarbon solvent mixture based upon the stream temperature and the threshold maximum pressure. The systems may include a hydrocarbon production system that may be configured to perform the methods and/or that may include an injection well, an injectant supply assembly, and a production well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of Canadian Patent Application 2,824,549 filed Aug. 22, 2013 entitled SYSTEMS AND METHODS FOR ENHANCING PRODUCTION OF VISCOUS HYDROCARBONS FROM A SUBTERRANEAN FORMATION, the entirety of which is incorporated by reference herein.

FIELD

The present disclosure is directed generally to systems and methods for enhancing production of viscous hydrocarbons from a subterranean formation, and more particularly to systems and methods that utilize a hydrocarbon solvent mixture to reduce a viscosity of the viscous hydrocarbons.

BACKGROUND

Viscous hydrocarbons, which also may be referred to herein as heavy oils and/or as bitumen, represent a significant fraction of worldwide hydrocarbon reserves. These viscous hydrocarbons may have a relatively high viscosity, precluding their production, or at least economic production, by flowing from a subterranean formation. Several methods have been utilized to decrease the viscosity of the viscous hydrocarbons, thereby decreasing a resistance to flow thereof and/or permitting production of the viscous hydrocarbons from the subterranean formation by piping, flowing, and/or pumping the viscous hydrocarbons from the subterranean formation. While each of these methods may be effective under certain conditions, they each possess inherent limitations.

As an illustrative, non-exclusive example, steam injection may be utilized to heat the viscous hydrocarbons and to thereby decrease their viscosity. While water and/or steam may represent an effective heat transfer medium, the pressure required to produce saturated steam at a desired temperature may be relatively high, limiting the applicability of steam recovery processes to high pressure operation and/or requiring a large amount of energy to heat the steam and decreasing an overall thermal efficiency of a viscous hydrocarbon recovery process. In addition, water and/or steam may damage certain subterranean formations.

As another illustrative, non-exclusive example, cold and/or heated solvents have been injected into a subterranean formation to decrease the viscosity of viscous hydrocarbons that are present within the subterranean formation. These methods traditionally inject a pure (i.e., single-component), or at least substantially pure, volatile solvent, such as propane, into the subterranean formation and permit the solvent to dissolve the viscous hydrocarbons, dilute the viscous hydrocarbons, and/or transfer thermal energy to the viscous hydrocarbons. While effective under certain conditions, these traditional solvent injection processes suffer from limited injection temperature and/or pressure operating ranges, an inability to effectively decrease the viscosity of the viscous hydrocarbons, and/or challenges associated with maintaining the traditional solvent in a vaporous state during transport to the subterranean formation. Thus, there exists a need for improved systems and methods for enhancing production of viscous hydrocarbons from a subterranean formation.

SUMMARY

A method of enhancing production of viscous hydrocarbons from a subterranean formation may comprise heating a hydrocarbon solvent mixture to generate a vapor stream at a stream temperature, wherein: (i) the hydrocarbon solvent mixture includes a heavy hydrocarbon fraction that consists essentially of hydrocarbons with five or more carbon atoms and comprises greater than 30 mole percent of the hydrocarbon solvent mixture; and (ii) the heavy hydrocarbon fraction includes a first compound, which has at least five carbon atoms and comprises at least 10 mole percent of the vapor stream, and a second compound, which has more carbon atoms than the first compound and comprises at least 10 mole percent of the vapor stream; injecting the vapor stream into the subterranean formation via an injection well, which extends within the subterranean formation, to decrease a viscosity of the viscous hydrocarbons within the subterranean formation and thereby generate reduced-viscosity hydrocarbons; and producing the reduced-viscosity hydrocarbons from the subterranean formation via a production well, which extends within the subterranean formation, wherein the production well is spaced apart from the injection well.

A method of enhancing production of viscous hydrocarbons from a subterranean formation may comprise heating a hydrocarbon solvent mixture to generate a vapor stream at a stream temperature of 30-250° C., wherein the hydrocarbon solvent mixture includes a first compound and a second compound with more carbon atoms than the first compound; injecting the vapor stream into the subterranean formation via an injection well that extends within the subterranean formation to decrease a viscosity of the viscous hydrocarbons within the subterranean formation and thereby generate reduced-viscosity hydrocarbons; and producing the reduced-viscosity hydrocarbons from the subterranean formation via a production well that extends within the subterranean formation, wherein the production well is spaced apart from the injection well; wherein a vapor pressure of the hydrocarbon solvent mixture is less than a threshold maximum pressure of the subterranean formation.

A method of selecting a composition of a hydrocarbon solvent mixture for injection into a subterranean formation to enhance production of viscous hydrocarbons therefrom, wherein the hydrocarbon solvent mixture is injected into the subterranean formation as a vapor stream at an injection pressure may comprise determining a threshold maximum pressure of the subterranean formation; determining a stream temperature at which the vapor stream is to be injected into the subterranean formation; and selecting the composition of the hydrocarbon solvent mixture based, at least in part, on the stream temperature and the threshold maximum pressure, wherein the selecting includes: (i) selecting a first proportion of the hydrocarbon solvent mixture that comprises a first compound with at least five carbon atoms, wherein the first proportion comprises at least 10 mole percent of the hydrocarbon solvent mixture; and (ii) selecting a second proportion of the hydrocarbon solvent mixture that comprises a second compound with more carbon atoms than the first compound, wherein the second proportion comprises at least 10 mole percent of the hydrocarbon solvent mixture.

A hydrocarbon production system may comprise an injection well that extends within a subterranean formation; an injectant supply assembly that is configured to provide a vapor stream to the injection well to generate reduced-viscosity hydrocarbons within the subterranean formation, the injectant supply assembly comprising: (i) a hydrocarbon solvent mixture, wherein the hydrocarbon solvent mixture includes a heavy hydrocarbon fraction that consists essentially of hydrocarbons with five or more carbon atoms and comprises greater than 30 mole percent of the hydrocarbon solvent mixture, and further wherein the heavy hydrocarbon fraction includes a first compound, which has at least five carbon atoms and comprises at least 10 mole percent of the hydrocarbon solvent mixture, and a second compound, which has more carbon atoms than the first compound and comprises at least 10 mole percent of the hydrocarbon solvent mixture; and (ii) a vaporization assembly that is configured to receive and vaporize the hydrocarbon solvent mixture to generate the vapor stream; and a production well that is spaced apart from the injection well and extends within the subterranean formation, wherein the production well is configured to receive the reduced-viscosity hydrocarbons and to convey the reduced-viscosity hydrocarbons from the subterranean formation.

The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of a hydrocarbon production system.

FIG. 2 is a plot of vapor pressure vs. temperature for a plurality of hydrocarbons.

FIG. 3 is a histogram depicting a carbon content of compounds that may be present in a gas plant condensate.

FIG. 4 is a flowchart depicting disclosure method of enhancing production of viscous hydrocarbons from a subterranean formation.

FIG. 5 is a flowchart depicting disclosure method of selecting a composition of a hydrocarbon solvent mixture.

It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.

DETAILED DESCRIPTION

For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

FIGS. 1 and 4-5 provide illustrative, non-exclusive examples of hydrocarbon production systems 10 according to the present disclosure, of methods 100 according to the present disclosure of enhancing production of viscous hydrocarbons from a subterranean formation, and/or of methods 200 according to the present disclosure of selecting a composition of a hydrocarbon solvent mixture for injection into the subterranean formation as a vapor stream. All elements and/or method steps may not be labeled in each of FIGS. 1 and 4-5, but reference numerals associated therewith may be utilized herein for consistency. Elements, components, features, and/or method steps that are discussed herein with reference to one or more of FIGS. 1 and 4-5 may be included in and/or utilized with any of FIGS. 1 and 4-5 without departing from the scope of the present disclosure.

In general, elements and/or method steps that are likely to be included are illustrated in solid lines, while elements and/or method steps that may be optional are illustrated in dashed lines. However, elements and/or method steps that are shown in solid lines are not necessarily essential, and an element and/or method step shown in solid lines may be omitted without departing from the scope of the present disclosure.

FIG. 1 is a schematic representation of a hydrocarbon production system 10 that may be utilized with, may be included in, and/or may include the systems and methods according to the present disclosure. Hydrocarbon production system 10 may include an injection well 30 and a production well 70 that extend between a surface region 20 and a subterranean formation 24 that is present within a subsurface region 22.

Injection well 30 may be in fluid communication with an injectant supply system 40. Injection well 30 may be configured to receive a hydrocarbon solvent mixture 44 from any suitable source (e.g., a storage structure 42). The hydrocarbon solvent mixture 44 may be provided to a vaporization assembly 50 to generate a vapor stream 52. The vapor stream 52 may be provided to subterranean formation 24 via injection well 30.

Once provided to the subterranean formation, the vapor stream 52 may condense within a vapor chamber 60. When the vapor stream 52 condenses, the vapor stream 52 may release latent heat (or latent heat of condensation), transfer thermal energy to the subterranean formation, and/or generate a condensate 54. Condensation of the vapor stream 52 may heat viscous hydrocarbons 26 that may be present within the subterranean formation, thereby decreasing a viscosity of the viscous hydrocarbons. Vapor stream 52 and/or condensate 54 may combine with, mix with, be dissolved in, dissolve, and/or dilute viscous hydrocarbons 26, thereby further decreasing the viscosity of the viscous hydrocarbons.

The energy transfer between vapor stream 52 and viscous hydrocarbons 26 and/or the mixing of vapor stream 52 with viscous hydrocarbons 26 may generate reduced-viscosity hydrocarbons 74, which may flow to production well 70. After flowing to the production well 70, the reduced-viscosity hydrocarbons 74 may be produced from the subterranean formation as a reduced-viscosity hydrocarbon mixture 72. The reduced-viscosity hydrocarbon mixture may comprise reduced-viscosity hydrocarbons 74, vapor stream 52, and/or condensate 54 in any suitable ratio and/or relative proportion.

Hydrocarbon production system 10 may include a condensate recovery system 77. The condensate recovery system 77 may include and/or be a separation assembly 78. Condensate recovery system 77 may receive reduced-viscosity hydrocarbon mixture 72. Condensate recovery system 77 may separate the reduced-viscosity hydrocarbon mixture into reduced-viscosity hydrocarbons 74, light hydrocarbon gasses 75, and/or recovered hydrocarbon solvent 76.

Reduced-viscosity hydrocarbons 74 may be removed from the hydrocarbon production system, utilized in another downstream process of the hydrocarbon production system, and/or pipelined or otherwise transported to a suitable processing site, such as a hydrocarbon refinery, for further processing.

Recovered hydrocarbon solvent 76 may be utilized as a feed stream 43 that may be combined with (or may be) hydrocarbon solvent mixture 44 to generate vapor stream 52.

Light hydrocarbon gasses 75 may include hydrocarbons and/or carbon compounds with four or fewer carbon atoms, such as methane, ethane, propane, and/or butane. Light hydrocarbon gasses 75 may be provided to vaporization assembly 50 as a fuel stream that may be combusted to heat hydrocarbon solvent mixture 44.

Hydrocarbon production system 10 may include a solvent purification system 79. Solvent purification system 79 may include a purification assembly 80. Solvent purification system 79 may be configured to receive a feed stream 43 from any suitable source. For example, feed stream 43 may be provided by storage structure 42 and/or may be separated from reduced-viscosity hydrocarbons 72 and recovered hydrocarbon solvent 76. Regardless of the source of feed stream 43, the solvent purification system 79 may be configured to remove one or more components from the feed stream 43 to generate hydrocarbon solvent mixture 44 with a target, or desired, composition. The hydrocarbon solvent mixture then may be provided to vaporization assembly 50 to generate vapor stream 52.

Injectant supply system 40 may receive hydrocarbon solvent mixture 44, such as from storage structure 42. Injectant supply system 40 may vaporize the hydrocarbon solvent mixture within vaporization assembly 50 to generate vapor stream 52. Injectant supply system 40 may receive recovered hydrocarbon solvent 76 from condensate recovery system 77. Injectant supply system 40 may vaporize the recovered hydrocarbon solvent within vaporization assembly 50 to generate vapor stream 52. Injectant supply system 40 may receive feed stream 43, such as from storage structure 42 and/or from condensate recovery system 77. Injectant supply system may purify the feed stream within purification assembly 80 to generate hydrocarbon solvent mixture 44, with the hydrocarbon solvent mixture then being vaporized within vaporization assembly 50 to generate vapor stream 52.

As discussed, conventional hydrocarbon production systems that utilize an injected vapor stream to decrease the viscosity of high viscosity hydrocarbons traditionally utilize a pure (i.e., single-component), or at least substantially pure, injected vapor stream that comprises a light hydrocarbon, such as propane. In contrast, the systems and methods according to the present disclosure may utilize hydrocarbon solvent mixture 44 to generate vapor stream 52. Hydrocarbon solvent mixture 44 may include a heavy hydrocarbon fraction that comprises, consists of, or consists essentially of hydrocarbons with five or more carbon atoms. The heavy hydrocarbon fraction may comprise greater than or equal to 10 mole percent, greater than or equal to 20 mole percent, greater than or equal to 30 mole percent greater than or equal to 40 mole percent, greater than or equal to 50 mole percent, greater than or equal to 60 mole percent, greater than or equal to 70 mole percent, or greater than or equal to 80 mole percent of the hydrocarbon solvent mixture. Additionally or alternatively, the heavy hydrocarbon fraction also may comprise less than or equal to 99 mole percent, less than or equal to 95 mole percent, less than or equal to 90 mole percent, less than or equal to 80 mole percent, less than or equal to 70 mole percent, less than or equal to 60 mole percent, or less than or equal to 50 mole percent of the hydrocarbon solvent mixture. Suitable ranges may include combinations of any upper and lower amount of mole percentage listed above. Additional examples of suitable mole percentages may include any of the illustrative threshold amounts listed above.

The heavy hydrocarbon fraction may include at least a first compound that has five or more carbon atoms and a second compound that has more carbon atoms than the first compound. The first compound and the second compound each may comprise at least 10 mole percent of hydrocarbon solvent mixture 44. For example, the first and/or second compounds may comprise at least 20 mole percent, at least 30 mole percent, at least 40 mole percent, at least 50 mole percent, at least 60 mole percent, at least 70 mole percent, or at least 80 mole percent of the hydrocarbon solvent mixture. Suitable ranges may include combinations of any upper and lower amount of mole percentage listed above.

The heavy hydrocarbon fraction may comprise any suitable hydrocarbon molecules, materials, and/or compounds. For example, the heavy hydrocarbon fraction may comprise one or more of alkanes, n-alkanes, branched alkanes, alkenes, n-alkenes, branched alkenes, alkynes, n-alkynes, branched alkynes, aromatic hydrocarbons, and/or cyclic hydrocarbons.

As used herein, a “compound that has five or more carbon atoms” may include any suitable single chemical species that includes five or more carbon atoms. A “compound that has five or more carbon atoms” also may include any suitable mixture of chemical species. Each of the chemical species in the mixture of chemical species may include five or more carbon atoms and each of the chemical species in the mixture of chemical species also may include the same number of carbon atoms as the other chemical species in the mixture of chemical species.

For example, a compound that has five carbon atoms may include a pentane, n-pentane, a branched pentane, cyclopentane, a pentene, n-pentene, a branched pentene, cyclopentene, a pentyne, n-pentyne, a branched pentyne, cyclopentyne, methylbutane, dimethylpropane, ethylpropane, and/or any other hydrocarbon with five carbon atoms. A compound with six carbon atoms, seven carbon atoms, or eight carbon atoms may include a single chemical species with six carbon atoms, seven carbon atoms, or eight carbon atoms, respectively, and/or may include a mixture of chemical species that each include six carbon atoms, seven carbon atoms, or eight carbon atoms, respectively.

Generating vapor stream 52 from hydrocarbon solvent mixture 44 may provide advantages over more traditional hydrocarbon production systems that utilize an injected vapor stream that is formed from a substantially pure light hydrocarbon. For example, and as illustrated in FIG. 2 (which is a plot of vapor pressure vs. temperature for a number of hydrocarbons with varying carbon content), compounds with a larger number of carbon atoms generally exhibit a lower vapor pressure at a given temperature when compared to compounds with a smaller number of carbon atoms. Thus, injecting vapor stream 52 that is formed from hydrocarbon solvent mixture 44, a majority of which comprises compounds with five or more carbon atoms, may permit injecting the vapor stream at a lower pressure for a given temperature when compared to propane injection and/or may permit tailoring (i.e., selecting, regulating, and/or controlling) a temperature-pressure behavior of the vapor stream to a given subterranean formation.

Vapor stream 52 may be injected into subterranean formation 24 at a stream temperature. A composition of hydrocarbon solvent mixture 44 may be selected such that the vapor pressure of the hydrocarbon solvent mixture at the stream temperature is less than a threshold maximum pressure of the subterranean formation. This may prevent damage to the subterranean formation and/or escape of vapor stream 52 from the subterranean formation. Threshold maximum pressures may include, for example, a characteristic pressure of the subterranean formation, such as a fracture pressure of the subterranean formation, a hydrostatic pressure within the subterranean formation, a lithostatic pressure within the subterranean formation, a gas cap pressure for a gas cap that is present within the subterranean formation, and/or an aquifer pressure for an aquifer that is located above and/or under the subterranean formation. The above-mentioned pressures may be measured and/or determined in any suitable manner. For example, this may include measuring a selected pressure with a downhole pressure sensor, calculating the pressure from any suitable property and/or characteristic of the subterranean formation, and/or estimating the pressure, such as via modeling the subterranean formation. The threshold pressures disclosed herein may be selected to correspond in any suitable or desired manner to one or more of these measured or calculated pressures. For example, the threshold pressures disclosed herein may be selected to be, to be greater than, to be less than, to be within a selected range of, to be a selected percentage of, to be within a selected constant of, etc. one or more of these selected or measured pressures. A threshold pressure may be a user-selected, or operator-selected, value that does not directly correspond to a measured or calculated pressure.

The threshold maximum pressure also may be related to and/or based upon the characteristic pressure of the subterranean formation. This may include threshold maximum pressures that are less than or equal to 95%, less than or equal to 90%, less than or equal to 85%, less than or equal to 80%, less than or equal to 75%, less than or equal to 70%, less than or equal to 65%, less than or equal to 60%, less than or equal to 55%, or less than or equal to 50% of the characteristic pressure for the subterranean formation and/or threshold maximum pressures that are at least 20%, at least 25%, at least 30%, at least 35%, at least 40%, at least 45%, at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, or at least 80% of the characteristic pressure for the subterranean formation. Suitable ranges may include combinations of any upper and lower amount of characteristic pressure listed above. Additional examples of suitable threshold maximum pressures may include any of the illustrative threshold amounts listed above.

Non-exclusive examples of vapor pressures for hydrocarbon solvent mixtures that may be utilized with and/or included in the systems and methods according to the present disclosure include vapor pressures that are greater than a lower threshold pressure of at least 0.2 megapascals (MPa), at least 0.3 MPa, at least 0.4 MPa, at least 0.5 MPa, at least 0.6 MPa, at least 0.7 MPa, at least 0.8 MPa, at least 0.9 MPa, at least 1 MPa, at least 1.1 MPa, at least 1.2 MPa, at least 1.3 MPa, at least 1.4 MPa, at least 1.5 MPa, at least 1.6 MPa, at least 1.7 MPa, at least 1.8 MPa, at least 1.9 MPa, at least 2 MPa, at least 2.1 MPa, at least 2.2 MPa, at least 2.3 MPa, at least 2.4 MPa, and/or at least 2.5 MPa. Additionally or alternatively, the vapor pressure for the hydrocarbon solvent mixture may be less than an upper threshold pressure that is less than or equal to 3 MPa, less than or equal to 2.9 MPa, less than or equal to 2.8 MPa, less than or equal to 2.7 MPa, less than or equal to 2.6 MPa, less than or equal to 2.5 MPa, less than or equal to 2.4 MPa, less than or equal to 2.3 MPa, less than or equal to 2.2 MPa, less than or equal to 2.1 MPa, less than or equal to 2 MPa, less than or equal to 1.9 MPa, less than or equal to 1.8 MPa, less than or equal to 1.7 MPa, less than or equal to 1.6 MPa, less than or equal to 1.5 MPa, less than or equal to 1.4 MPa, less than or equal to 1.3 MPa, less than or equal to 1.2 MPa, less than or equal to 1.1 MPa, less than or equal to 1 MPa, less than or equal to 0.9 MPa, less than or equal to 0.8 MPa, less than or equal to 0.7 MPa, less than or equal to 0.6 MPa, less than or equal to 0.5 MPa, less than or equal to 0.4 MPa, and/or less than or equal to 0.3 MPa. Suitable ranges may include combinations of any upper and lower amount of pressure listed above. Additional examples of suitable pressures may include any of the illustrative threshold amounts listed above.

Non-exclusive examples of stream temperatures of vapor stream 52 when it is injected into injection well 30 include stream temperatures of at least 30° C., at least 35° C., at least 40° C., at least 45° C., at least 50° C., at least 55° C., at least 60° C., at least 65° C., at least 70° C., at least 75° C., at least 80° C., at least 85° C., at least 90° C., at least 95° C., at least 100° C., at least 105° C., at least 110° C., at least 115° C., at least 120° C., at least 125° C., at least 130° C., at least 135° C., at least 140° C., at least 145° C., at least 150° C., at least 155° C., at least 160° C., at least 165° C., at least 170° C., at least 175° C., at least 180° C., at least 185° C., at least 190° C., at least 195° C., at least 200° C., at least 205° C., and/or at least 210° C. Additionally or alternatively, the stream temperature also may be less than or equal to 250° C., less than or equal to 240° C., less than or equal to 230° C., less than or equal to 220° C., less than or equal to 210° C., less than or equal to 200° C., less than or equal to 190° C., less than or equal to 180° C., less than or equal to 170° C., less than or equal to 160° C., less than or equal to 150° C., less than or equal to 140° C., less than or equal to 130° C., less than or equal to 120° C., less than or equal to 110° C., less than or equal to 100° C., less than or equal to 90° C., less than or equal to 80° C., less than or equal to 70° C., less than or equal to 60° C., less than or equal to 50° C., and/or less than or equal to 40° C. Suitable ranges may include combinations of any upper and lower amount of stream temperatures listed above. Additional examples of suitable stream temperatures may include any of the illustrative threshold amounts listed above.

The composition of hydrocarbon solvent mixture 44 may be selected such that a dew point temperature of vapor stream 52 and a bubble point temperature of the hydrocarbon solvent mixture differ by at least a threshold temperature difference. Illustrative, non-exclusive examples of the threshold temperature difference include threshold temperature differences of at least 10° C., at least 15° C., at least 20° C., at least 25° C., at least 30° C., at least 35° C., at least 40° C., at least 45° C., at least 50° C., at least 55° C., at least 60° C., at least 65° C., at least 70° C., at least 75° C., at least 80° C., at least 85° C., at least 90° C., at least 95° C., or at least 100° C. Additional examples and/or ranges of temperature differences may be based upon the difference between any include combinations of any upper and lower stream temperatures listed above.

When vapor stream 52 is injected into subterranean formation 24 via injection well 30 (as illustrated in FIG. 1), the vapor stream may decrease in temperature (or lose thermal energy) while being conveyed through the injection well to the subterranean formation and/or while being conveyed through the subterranean formation from injection well 30 to an interface 62 between vapor chamber 60 and viscous hydrocarbons 26 that are not within the vapor chamber. Thus, and for traditional single-component vapor streams, the vapor stream must be superheated significantly prior to being injected into the subterranean formation and/or a significant portion of the vapor stream will condense prior to reaching interface 62.

However, and since vapor stream 52 according to the present disclosure is formed from hydrocarbon solvent mixture 44, only a portion, such as a minority portion, of the vapor stream (such as a lower vapor pressure portion, a higher molecular weight portion, and/or a portion that is formed from hydrocarbon compounds with a greater number of carbon atoms) may condense during transport between surface region 20 and subterranean formation 24 and/or during transport between injection well 30 and interface 62. Thus, this portion of vapor stream 52 may act as a “thermal buffer” for a remainder of vapor stream 52, decreasing a potential for undesired condensation of the remainder of the vapor stream. This may increase an overall efficiency of hydrocarbon production system 10, may permit the hydrocarbon production system to operate with less energy, and/or may permit vapor stream 52 to extend farther into subterranean formation 24 prior to condensing within the subterranean formation, when compared to traditional vapor injection processes that do not utilize hydrocarbon solvent mixture 44.

Hydrocarbon solvent mixture 44 may be obtained from any suitable source. As illustrative, non-exclusive examples, hydrocarbon solvent mixture 44 may include, be obtained from, and/or be a gas plant condensate and/or a crude oil refinery condensate. FIG. 3 is a histogram depicting a mole fraction of hydrocarbons that may be present in a given gas plant condensate as a function of the carbon content of the hydrocarbons. As may be seen in FIG. 3, the gas plant condensate may include a significant fraction of compounds with five or more carbon atoms and thus may be suitable for use as hydrocarbon solvent mixture 44, either directly or after further purification and/or separation (such as via solvent purification system 79).

Thus, and when hydrocarbon solvent mixture 44 includes gas plant condensate (such as the gas plant condensate of FIG. 3), solvent purification system 79 may be utilized to remove one or more components from the gas plant condensate to generate a desired composition for the hydrocarbon solvent mixture. For example, solvent purification system 79 may remove at least a portion of the compounds with four or fewer carbon atoms from the gas plant condensate. As another example, solvent purification system 79 may remove at least a portion of one or more of the compounds with five or more carbon atoms from the gas plant condensate.

Hydrocarbon solvent mixture 44 may define any suitable composition. As illustrative, non-exclusive examples, a majority fraction, at least 50 mole percent, at least 60 mole percent, at least 70 mole percent, at least 80 mole percent, at least 90 mole percent, or at least 95 mole percent of hydrocarbon solvent mixture 44 may comprise a compound with five carbon atoms, a compound with six carbon atoms, a compound with seven carbon atoms, and/or a compound with eight carbon atoms. As additional illustrative, non-exclusive examples, the first compound may be pentane and/or the second compound may be hexane.

Hydrocarbon solvent mixture 44 may comprise any suitable number of compounds and/or chemical species. The hydrocarbon solvent mixture may include a third compound that includes more carbon atoms than the second compound. When the hydrocarbon solvent mixture includes the third compound, the third compound may comprise any suitable portion, or fraction, of the hydrocarbon solvent mixture. The third compound may comprise at least 20 mole percent, at least 30 mole percent, at least 40 mole percent, at least 50 mole percent, at least 60 mole percent, or at least 70 mole percent of the hydrocarbon solvent mixture.

The hydrocarbon solvent mixture 44 may include a light hydrocarbon fraction that includes hydrocarbons with fewer than five carbon atoms, such as hydrocarbons with one carbon atom, two carbon atoms, three carbon atoms, and/or four carbon atoms; however, this light hydrocarbon fraction (when present) may comprise a minority portion of the hydrocarbon solvent mixture. The light hydrocarbon fraction may comprise at least 5 mole percent, at least 10 mole percent, at least 15 mole percent, at least 20 mole percent, at least 30 mole percent, at least 40 mole percent, at least 50 mole percent, or at least 60 mole percent of the hydrocarbon solvent mixture. The light hydrocarbon fraction may comprise less than or equal to 70 mole percent, less than 60 or equal to mole percent, less than or equal to 50 mole percent, less than or equal to 40 mole percent, less than or equal to 30 mole percent, less than or equal to 20 mole percent, less than or equal to 15 mole percent, or less than or equal to 10 mole percent of the hydrocarbon solvent mixture. Suitable ranges may include combinations of any upper and lower amount of hydrocarbon fractions listed above. Additional examples of suitable mole percentages of light hydrocarbons may include any of the illustrative threshold amounts listed above.

Condensate recovery system 77 may include any suitable structure, such as at least one separation assembly 78, that is configured to separate at least a portion of condensate 54 from reduced-viscosity hydrocarbon mixture 72 and/or from reduced-viscosity hydrocarbons 74 that are present within the reduced-viscosity hydrocarbon mixture and to generate recovered hydrocarbon solvent 76. This may include any suitable (single stage) separation vessel, (multistage) distillation assembly, liquid-liquid separation, or extraction, assembly and/or any suitable gas-liquid separation, or extraction, assembly. Condensate recovery system 77 may include a recycle conduit 82 that is configured to convey the recovered hydrocarbon solvent stream, which also may be referred to herein as condensate 54 and/or as a portion of the condensate stream, to vaporization assembly 50.

Solvent purification system 79 may include any suitable structure, such as at least one purification assembly 80, that may be configured to receive any suitable feed stream 43, such as a hydrocarbon feedstock stream and/or recovered hydrocarbon solvent 76, and to purify the feed stream to generate hydrocarbon solvent mixture 44. This may include any suitable liquid-liquid separation, or extraction, assembly, any suitable gas-liquid separation, or extraction, assembly, any suitable gas-gas separation, or extraction, assembly, single stage separation vessel, and/or any suitable (multistage) distillation assembly. In addition, solvent purification system 79 may be configured to produce hydrocarbon solvent mixture 44 with any suitable composition, such as those that are discussed herein. This may include removing compounds with fewer than five carbon atoms from the feed stream to generate the hydrocarbon solvent mixture.

Vaporization assembly 50 may include any suitable structure that is configured to vaporize hydrocarbon solvent mixture 44 to generate vapor stream 52. Vaporization assembly 50 may include a heating assembly that is configured to heat and vaporize the hydrocarbon solvent mixture. Vaporization assembly 50 may include a steam co-injection assembly that is configured to co-inject steam into injection well 30 with hydrocarbon solvent mixture 44. The steam may heat and vaporize the hydrocarbon solvent mixture to generate vapor stream 52. This may include heating and vaporizing the hydrocarbon solvent mixture prior to the hydrocarbon solvent mixture being supplied to the injection well (as illustrated in FIG. 1). Additionally or alternatively, this also may include heating and vaporizing the hydrocarbon solvent mixture within the injection well (or subsequent to supply to the injection well).

Injection well 30 may include any suitable structure that may form a fluid conduit to convey vapor stream 52 to, or into, subterranean formation 24. Similarly, production well 70 may include any suitable structure that may form a fluid conduit to convey reduced-viscosity hydrocarbon mixture 72 from subterranean formation 24 to, toward, and/or proximal, surface region 20. As illustrated, for example, in FIG. 1, injection well 30 may be spaced apart from production well 70. Production well 70 may extend at least partially below injection well 30, may extend at least partially vertically below injection well 30, and/or may define a greater distance (or average distance) from surface region 20 when compared to injection well 30. At least a portion of production well 70 may be parallel to, or at least substantially parallel to, a corresponding portion of injection well 30. At least a portion of injection well 30, and/or of production well 70, may include a horizontal, or at least substantially horizontal, portion.

FIG. 4 is a flowchart depicting methods 100 according to the present disclosure of enhancing production of viscous hydrocarbons from a subterranean formation. Methods 100 may include preheating at least a portion of the subterranean formation at 105, selecting a composition of a hydrocarbon solvent mixture at 110, and/or regulating the composition of the hydrocarbon solvent mixture at 115. Methods 100 may include heating the hydrocarbon solvent mixture to generate a vapor stream at a stream temperature at 120 and injecting the vapor stream into the subterranean formation at 125. Methods 100 also may include condensing the vapor stream within the subterranean formation at 130 to generate a condensate and/or generating reduced-viscosity hydrocarbons at 135. Methods 100 further may include producing the reduced-viscosity hydrocarbons at 140 and may include producing the condensate at 145 and/or recycling the condensate at 150.

Preheating a portion of the subterranean formation at 105 may include preheating, or providing thermal energy to, the subterranean formation in any suitable manner and may be performed prior to the injecting at 125. The preheating at 105 may include electrically preheating the subterranean formation, chemically preheating the subterranean formation, and/or injecting a preheating steam stream into the subterranean formation. The preheating at 105 may include preheating any suitable portion of the subterranean formation, such as a portion of the subterranean formation that is proximal to the injection well, a portion of the subterranean formation that is proximal to the production well, and/or a portion of the subterranean formation that defines a vapor chamber that receives the vapor stream.

Selecting the composition of a hydrocarbon solvent mixture at 110 may include selecting the composition of the hydrocarbon solvent mixture such that a vapor pressure of the hydrocarbon solvent mixture is less than a threshold maximum pressure of the subterranean formation, such that the vapor pressure of the hydrocarbon solvent mixture is at least a lower threshold pressure, and/or such that the vapor pressure of the hydrocarbon solvent mixture is less than an upper threshold pressure. Illustrative, non-exclusive examples of the threshold maximum pressure, the lower threshold pressure, and the upper threshold pressure are discussed herein. Additionally or alternatively, the selecting at 110 also may include selecting using any of the subsequently described methods 200.

Regulating the composition of the hydrocarbon solvent mixture at 115 may include regulating the composition, or chemical composition, of the hydrocarbon solvent mixture in any suitable manner. The regulating at 115 may include receiving a hydrocarbon feedstock, or a feed stream, that comprises a desired composition for the hydrocarbon solvent mixture, and the regulating further may include utilizing the hydrocarbon feedstock as the hydrocarbon solvent mixture. The regulating at 115 may include receiving the hydrocarbon feedstock and altering a composition of the hydrocarbon feedstock to generate the hydrocarbon solvent mixture. The altering may include diluting the hydrocarbon feedstock, distilling the hydrocarbon feedstock, removing a portion of the hydrocarbon feedstock, and/or decreasing a proportion of the hydrocarbon feedstock that comprises compounds with fewer than five carbon atoms to generate the hydrocarbon solvent mixture. Illustrative, non-exclusive examples of the composition, or the desired composition, of the hydrocarbon solvent mixture are discussed in more detail herein.

Heating the hydrocarbon solvent mixture to generate a vapor stream at 120 may include heating the hydrocarbon solvent mixture in any suitable manner to generate the vapor stream at a suitable stream temperature. Illustrative, non-exclusive examples of the stream temperature are disclosed herein.

The heating at 120 may include directly heating the hydrocarbon solvent mixture in a surface region to generate the vapor stream. The heating at 120 may include co-injecting the hydrocarbon solvent mixture and a steam stream to vaporize the hydrocarbon solvent mixture. When the heating at 120 includes co-injecting the steam stream, the steam stream may be a saturated steam stream. Additionally or alternatively, the co-injecting may include co-injecting at least 5, at least 6, at least 7, at least 8, at least 9 at least 10, at least 20, at least 25, at least 50, at least 75, or at least 100 moles of the hydrocarbon solvent mixture for each mole of steam.

Injecting the vapor stream into the subterranean formation at 125 may include injecting the vapor stream via an injection well that extends within the subterranean formation and/or injecting the vapor stream to decrease a viscosity of viscous hydrocarbons that may be present within the subterranean formation. This may include injecting to facilitate and/or produce the generating at 135.

The injecting at 125 may include flowing the vapor stream through, or through at least a portion of, the injection well and into the subterranean formation. The injecting at 125 also may include contacting the vapor stream with the viscous hydrocarbons within the subterranean formation.

Condensing the vapor stream within the subterranean formation at 130 may include condensing any suitable portion of the vapor stream to release a latent heat of condensation of the vapor stream, heat the subterranean formation, heat the viscous hydrocarbons, and/or generate the reduced-viscosity hydrocarbons within the subterranean formation. The condensing at 130 may include condensing a majority, at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 95%, at least 99%, or substantially all of the vapor stream within the subterranean formation. The condensing at 130 may include generating a condensate, which also may be referred to herein as a condensate stream, from the vapor stream and/or within the subterranean formation. The condensing at 130 may include regulating a temperature within the subterranean formation to facilitate, or permit, the condensing at 130.

Generating reduced-viscosity hydrocarbons at 135 may include generating the reduced-viscosity hydrocarbons in any suitable manner. The generating at 135 may be facilitated by, produced by, and/or a result of the injecting at 125 and/or the condensing at 130. The generating at 135 also may include dissolving the condensate in the viscous hydrocarbons, dissolving the viscous hydrocarbons in the condensate, and/or diluting the viscous hydrocarbons with the condensate to generate the reduced-viscosity hydrocarbons.

Producing the reduced-viscosity hydrocarbons at 140 may include producing the reduced-viscosity hydrocarbons via any suitable production well, which may extend within the subterranean formation and/or may be spaced apart from the injection well. This may include flowing the reduced-viscosity hydrocarbons from the subterranean formation, through the production well, and to, proximal to, and/or toward the surface region.

The producing at 140 may include producing asphaltenes. The asphaltenes may be present within the subterranean formation and/or within the viscous hydrocarbons. The asphaltenes may be produced as a portion of the reduced-viscosity hydrocarbons (and/or the reduced-viscosity hydrocarbons may include, or comprise, asphaltenes). The injecting at 125 may include injecting into a stimulated region of the subterranean formation that includes asphaltenes, and the producing at 140 may include producing at least a threshold fraction of the asphaltenes from the stimulated region. This may include producing at least 10 wt %, at least 20 wt %, at least 30 wt %, at least 40 wt %, at least 50 wt %, at least 60 wt %, at least 70 wt %, at least 80 wt %, or at least 90 wt % of the asphaltenes that are, or were, present within the stimulated region prior to the injecting at 125.

Producing the condensate at 145 may include producing the condensate, or condensate stream, that is generated during the condensing at 130. The producing at 145 may include producing the condensate with the reduced-viscosity hydrocarbons and/or producing a reduced-viscosity hydrocarbon mixture that includes the reduced-viscosity hydrocarbons and the condensate.

Recycling the condensate at 150 may include recycling the condensate in any suitable manner. The recycling at 150 may include separating at least a separated portion of the condensate from the reduced-viscosity hydrocarbon mixture and/or from the reduced-viscosity hydrocarbons. The recycling at 150 also may include utilizing at least a recycled portion of the condensate, which also may be referred to herein as a recovered hydrocarbon solvent, as, or as a portion of, the hydrocarbon solvent mixture and/or returning the recycled portion of the condensate to the subterranean formation via the injection well. The recycling at 150 further may include purifying the recycled portion of the condensate prior to utilizing the recycled portion of the condensate and/or prior to returning the recycled portion of the condensate to the subterranean formation.

FIG. 5 is a flowchart depicting illustrative, non-exclusive examples of methods 200 according to the present disclosure of selecting a composition of a hydrocarbon solvent mixture for injection into a subterranean formation as a vapor stream to enhance production of viscous hydrocarbons from the subterranean formation. Methods 200 may include determining a threshold maximum pressure for the subterranean formation at 210, determining a stream temperature at which the vapor stream is injected into the subterranean formation at 220, and selecting a composition of the hydrocarbon solvent mixture at 230. Methods 200 may include injecting the vapor stream into the subterranean formation at 240 and/or producing reduced-viscosity hydrocarbons from the subterranean formation at 250.

Determining the threshold maximum pressure for the subterranean formation at 210 may include determining any suitable threshold maximum pressure for the subterranean formation. Illustrative, non-exclusive examples of the threshold maximum pressure are discussed in more detail herein.

Determining the stream temperature at which the vapor stream is injected into the subterranean formation at 220 may include determining the stream temperature in any suitable manner. The determining at 220 may include determining a thermally efficient stream temperature. The determining at 220 may include determining a stream temperature at a viscosity, or average viscosity, of the viscous hydrocarbons. The determining at 220 may include determining a stream temperature at which a production rate of the viscous hydrocarbons from the subterranean formation is at least a threshold production rate. Illustrative, non-exclusive examples of the stream temperature are disclosed herein.

Selecting the composition of the hydrocarbon solvent mixture at 230 may include selecting the composition of the hydrocarbon solvent mixture based, at least in part, on the stream temperature and/or on the threshold maximum pressure. Additionally or alternatively, the selecting at 230 also may include selecting, at 232, a first proportion of the hydrocarbon solvent mixture that comprises a first compound with at least five carbon atoms, selecting, at 234, a second proportion of the hydrocarbon solvent mixture that comprises a second compound with more carbon atoms than the first compound, and/or (optionally) selecting, at 236, a third (or additional) proportion of the hydrocarbon solvent mixture that comprises a third (or additional) compound with more carbon atoms than the second (or a prior) compound. The selecting at 230 further may include selecting such that the first proportion, the second proportion, and/or the third proportion (when present) individually comprise at least 10, at least 20, at least 30, at least 40, at least 50, or at least 60 mole percent of the hydrocarbon solvent mixture. Additionally or alternatively, the selecting at 230 also may include selecting such that the first compound, the second compound, and/or the third compound (when present) together comprise at least 10, at least 20, at least 30, at least 40, at least 50, at least 60, at least 70, at least 80, at least 90, at least 95, or at least 99 mole percent of the hydrocarbon solvent mixture and/or such that the hydrocarbon solvent mixture comprises at least 50, at least 60, at least 70, at least 80, at least 90, at least 95, or at least 99 mole percent hydrocarbons.

The selecting at 230 also may include selecting such that a vapor pressure of the hydrocarbon solvent mixture at a stream temperature of the vapor stream is less than the maximum threshold pressure of the subterranean formation. Illustrative, non-exclusive examples of the stream temperature are disclosed herein.

This selecting may include increasing the first proportion of the hydrocarbon solvent mixture and/or decreasing the second proportion of the hydrocarbon solvent mixture to increase the vapor pressure of the hydrocarbon solvent mixture. Additionally or alternatively, this may include decreasing the first proportion of the hydrocarbon solvent mixture and/or increasing the second proportion of the hydrocarbon solvent mixture to decrease the vapor pressure of the hydrocarbon solvent mixture.

The selecting at 230 also may include selecting such that the vapor pressure of the hydrocarbon solvent mixture is less than an upper threshold pressure and/or greater than a lower threshold pressure. Illustrative, non-exclusive examples of the upper threshold pressure and/or of the lower threshold pressure are disclosed herein.

When the viscous hydrocarbons include asphaltenes, the selecting at 230 further may include selecting such that at least a threshold fraction of the asphaltenes within the sample are soluble within the hydrocarbon solvent mixture at the temperature and pressure at which the hydrocarbon solvent mixture contacts the viscous hydrocarbons within the subterranean formation. This may include measuring the solubility of the asphaltenes within the hydrocarbon solvent mixture. This is in direct contrast to traditional solvent injection processes, which typically are unable to remove asphaltenes, or at least a significant fraction of the asphaltenes, from the subterranean formation.

Illustrative, non-exclusive examples of the threshold fraction include threshold fractions of at least 20 weight % (wt %), at least 30 wt %, at least 40 wt %, at least 50 wt %, at least 60 wt %, at least 70 wt %, at least 80 wt %, at least 90 wt %, at least 95 wt %, or at least 99 wt %. Additionally or alternatively, the selecting at 230 also may include selecting such that a solubility of the asphaltenes within the hydrocarbon solvent mixture is greater than a solubility of the asphaltenes in propane and/or butane.

Injecting the vapor stream into the subterranean formation at 240 may include injecting the vapor stream into the subterranean formation in any suitable manner to generate reduced-viscosity hydrocarbons within the subterranean formation. As an illustrative, non-exclusive example, the injecting at 240 may be at least substantially similar to the injecting at 125, which is discussed in more detail herein with reference to FIG. 4.

Producing reduced-viscosity hydrocarbons from the subterranean formation at 250 may include producing the reduced-viscosity hydrocarbons in any suitable manner. As an illustrative, non-exclusive example, the producing at 250 may be at least substantially similar to the producing at 140, which is discussed in more detail herein with reference to FIG. 4.

In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified.

In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, Implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industry.

The subject matter of the disclosure includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are novel and non-obvious. Other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the present disclosure. 

1. A method of enhancing production of viscous hydrocarbons from a subterranean formation, the method comprising: heating a hydrocarbon solvent mixture to generate a vapor stream at a stream temperature, wherein: (i) the hydrocarbon solvent mixture includes a heavy hydrocarbon fraction that consists essentially of hydrocarbons with five or more carbon atoms and comprises greater than 30 mole percent of the hydrocarbon solvent mixture; and (ii) the heavy hydrocarbon fraction includes a first compound, which has at least five carbon atoms and comprises at least 10 mole percent of the vapor stream, and a second compound, which has more carbon atoms than the first compound and comprises at least 10 mole percent of the vapor stream; injecting the vapor stream into the subterranean formation via an injection well that extends within the subterranean formation to decrease a viscosity of the viscous hydrocarbons within the subterranean formation and thereby generate reduced-viscosity hydrocarbons; and producing the reduced-viscosity hydrocarbons from the subterranean formation via a production well that extends within the subterranean formation, wherein the production well is spaced apart from the injection well.
 2. The method of claim 1, wherein a composition of the hydrocarbon solvent mixture is selected such that a vapor pressure of the hydrocarbon solvent mixture at the stream temperature is less than a threshold maximum pressure of the subterranean formation.
 3. The method of claim 1, wherein the stream temperature is at least 30° C. and less than 250° C.
 4. The method of claim 1, wherein the injecting includes condensing at least 50% of the vapor stream within the subterranean formation to transfer a latent heat of the vapor stream to the viscous hydrocarbons and generate the reduced-viscosity hydrocarbons and to generate a condensate from the vapor stream.
 5. The method of claim 4, wherein the method further includes at least one of dissolving the condensate in the viscous hydrocarbons, dissolving the viscous hydrocarbons in the condensate, and diluting the viscous hydrocarbons with the condensate to generate the reduced-viscosity hydrocarbons.
 6. The method of claim 4, wherein the producing includes producing the condensate with the reduced-viscosity hydrocarbons, and further wherein the method includes separating a separated portion of the condensate from the reduced-viscosity hydrocarbons and utilizing a recycled portion of the condensate as the hydrocarbon solvent mixture.
 7. The method of claim 6, wherein the method further includes purifying the recycled portion of the condensate prior to the utilizing.
 8. The method of claim 1, wherein the injecting includes injecting into a stimulated region of the subterranean formation, wherein the stimulated region includes asphaltenes, and further wherein the producing includes producing at least 50 wt % of the asphaltenes that are present within the stimulated region prior to the injecting.
 9. The method of claim 1, wherein the method further includes preheating a portion of the subterranean formation that is proximal to the injection well prior to the injecting the vapor stream.
 10. The method of claim 1, wherein the method further includes regulating a composition of the hydrocarbon solvent mixture, wherein the regulating includes receiving a hydrocarbon feedstock and altering a composition of the hydrocarbon feedstock to generate the hydrocarbon solvent mixture, and further wherein the altering includes decreasing a proportion of the hydrocarbon feedstock that comprises hydrocarbons with fewer than five carbon atoms.
 11. The method of claim 1, wherein the threshold maximum pressure includes at least one of a fracture pressure for the subterranean formation, a hydrostatic pressure within the subterranean formation, a lithostatic pressure within the subterranean formation, a gas cap pressure for a gas cap within the subterranean formation, and an aquifer pressure for an aquifer that is at least one of above and under the subterranean formation.
 12. A method of selecting a composition of a hydrocarbon solvent mixture for injection into a subterranean formation to enhance production of viscous hydrocarbons therefrom, wherein the hydrocarbon solvent mixture is injected into the subterranean formation as a vapor stream at an injection pressure, the method comprising: determining a threshold maximum pressure of the subterranean formation; determining a stream temperature at which the vapor stream is to be injected into the subterranean formation; and selecting the composition of the hydrocarbon solvent mixture based, at least in part, on the stream temperature and the threshold maximum pressure, wherein the selecting includes: (i) selecting a first proportion of the hydrocarbon solvent mixture that comprises a first compound with at least five carbon atoms, wherein the first proportion comprises at least 10 mole percent of the hydrocarbon solvent mixture; and (ii) selecting a second proportion of the hydrocarbon solvent mixture that comprises a second compound with more carbon atoms than the first compound, wherein the second proportion comprises at least 10 mole percent of the hydrocarbon solvent mixture.
 13. The method of claim 12, wherein the selecting includes selecting such that a vapor pressure of the hydrocarbon solvent mixture at the stream temperature is less than the threshold maximum pressure of the subterranean formation.
 14. The method of claim 12, wherein the selecting includes at least one of: (i) increasing the first proportion of the hydrocarbon solvent to increase a vapor pressure of the hydrocarbon solvent mixture; (ii) the second proportion of the hydrocarbon solvent mixture to increase the vapor pressure of the hydrocarbon solvent mixture; (iii) decreasing the first proportion of the hydrocarbon solvent mixture to decrease the vapor pressure of the hydrocarbon solvent mixture; and (iv) increasing the second proportion of the hydrocarbon solvent mixture to decrease the vapor pressure of the hydrocarbon solvent mixture.
 15. The method of claim 12, wherein the stream temperature is at least 30° C. and less than 250° C.
 16. The method of claim 12, wherein the selecting includes selecting such that the first compound and the second compound together comprise at least 50 mole percent of the hydrocarbon solvent mixture.
 17. The method of claim 12, wherein the selecting includes selecting such that at least 50 weight % of asphaltenes that are present within the subterranean formation are soluble within the hydrocarbon solvent mixture at the injection pressure and the stream temperature.
 18. The method of claim 12, wherein the vapor stream is injected into the subterranean formation at an injection pressure, and further wherein the selecting includes selecting such that a difference between a dew point of the vapor stream and a bubble point of the hydrocarbon solvent mixture is at least 10° C. at the injection pressure.
 19. The method of claim 12, wherein the determining the threshold maximum pressure includes determining at least one of a fracture pressure for the subterranean formation, a hydrostatic pressure within the subterranean formation, a lithostatic pressure within the subterranean formation, a gas cap pressure for a gas cap within the subterranean formation, and an aquifer pressure for an aquifer that is at least one of above and under the subterranean formation.
 20. The method of claim 12, wherein the method further includes injecting the vapor stream into the subterranean formation to generate reduced viscosity hydrocarbons within the subterranean formation.
 21. The method of claim 20, wherein the method further includes producing the reduced viscosity hydrocarbons from the subterranean formation.
 22. A hydrocarbon production system, comprising: an injection well that extends within a subterranean formation; an injectant supply assembly that is configured to provide a vapor stream to the injection well to generate reduced-viscosity hydrocarbons within the subterranean formation, the injectant supply assembly comprising: (i) a hydrocarbon solvent mixture, wherein the hydrocarbon solvent mixture includes a heavy hydrocarbon fraction that consists essentially of hydrocarbons with five or more carbon atoms and comprises greater than 30 mole percent of the hydrocarbon solvent mixture, and further wherein the heavy hydrocarbon fraction includes a first compound, which has at least five carbon atoms and comprises at least 10 mole percent of the hydrocarbon solvent mixture, and a second compound, which has more carbon atoms than the first compound and comprises at least 10 mole percent of the hydrocarbon solvent mixture; and (ii) a vaporization assembly that is configured to receive and vaporize the hydrocarbon solvent mixture to generate the vapor stream; and a production well that is spaced apart from the injection well and extends within the subterranean formation, wherein the production well is configured to receive the reduced-viscosity hydrocarbons and to convey the reduced-viscosity hydrocarbons from the subterranean formation.
 23. The system of claim 22, wherein, subsequent to being provided to the subterranean formation, the vapor stream condenses to a condensate stream, wherein the production well receives the condensate stream and conveys the condensate stream from the subterranean formation with the reduced-viscosity hydrocarbons, and further wherein the hydrocarbon production system further includes a condensate recovery system that is configured to separate at least a portion of the condensate stream from the reduced-viscosity hydrocarbons.
 24. The system of claim 23, wherein the hydrocarbon production system further includes a recycle conduit that is configured to convey the portion of the condensate stream to the vaporization assembly, wherein the vaporization assembly is configured to vaporize the portion of the condensate stream to generate the vapor stream.
 25. The system of claim 23, wherein the hydrocarbon production system further includes a purification system that is configured to receive a feed stream that includes at least one of a hydrocarbon feedstock stream and the condensate stream and to purify the feed stream to generate the hydrocarbon solvent mixture.
 26. The system of claim 22, wherein the hydrocarbon solvent mixture comprises at least one of a gas plant condensate and a crude oil refinery condensate.
 27. The system of claim 22, wherein at least 50 mole percent of the hydrocarbon solvent mixture comprises at least two of a compound with five carbon atoms, a compound with six carbon atoms, a compound with seven carbon atoms, and a compound with eight carbon atoms.
 28. The system of claim 22, wherein less than 30 mole percent of the hydrocarbon solvent mixture comprises a compound with one to three carbon atoms.
 29. The system of claim 22, wherein the production well extends at least partially below the injection well.
 30. The system of claim 22, wherein at least a portion of the production well is parallel to a corresponding portion of the injection well.
 31. The system of claim 22, wherein both of the injection well and the production well include a horizontal portion.
 32. The system of claim 22, wherein at least a portion of the production well is located vertically below a corresponding portion of the injection well.
 33. The system of claim 22, wherein the threshold maximum pressure is at least one of a fracture pressure for the subterranean formation, a hydrostatic pressure within the subterranean formation, a lithostatic pressure within the subterranean formation, a gas cap pressure for a gas cap within the subterranean formation, and an aquifer pressure for an aquifer that is above the subterranean formation. 